Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid (also known as a drilling mud) through the drill pipe and the drill bit and upwardly through the wellbore to the surface. The drilling fluid serves to control the wellbore pressures, lubricate the drill bit, and carry drill cuttings back to the surface. After the wellbore is drilled to the desired depth, the drill pipe and drill bit are typically withdrawn from the wellbore while the drilling fluid is left in the wellbore to provide hydrostatic pressure on the formation penetrated by the wellbore and thereby prevent formation fluids from flowing into the wellbore.
The next operation in completing the wellbore usually involves running a string of pipe, e.g., casing, in the wellbore. Primary cementing is then typically performed whereby a cement slurry is pumped down through the string of pipe and into the annulus between the string of pipe and the walls of the wellbore to allow the cement slurry to set into a hard mass, and thereby seal the annulus. The cement slurry ideally displaces the drilling fluid from the annulus. However, some intermixing usually occurs, and certain cement slurries are often incompatible with the components in certain drilling fluids.
Formate-based drilling fluids have emerged that can be used in a variety of applications such as for drilling and completing deep, high-temperature wells. Such fluids contain minimal solids and maintain Theological stability at relatively high temperatures. The formate-based drilling fluids typically comprise formate salts of alkali metals such as cesium formate and/or potassium formate, which are soluble in water. They advantageously form high-density brines, thus providing for good monitoring and control of the wellbore. In particular, the density of a formate-based drilling fluid can be varied depending on various factors. For example, a less dense fluid can be used to speed up drilling, or a more dense fluid can be used to prevent formation fluid from flowing into the wellbore when the formation fluid pressure is relatively high.
Due to its acidic nature, a formate-based drilling fluid is often buffered with an alkaline material such as a potassium carbonate to prevent corrosion and ensure that the fluid is chemically stable when used downhole. For example, a drilling fluid commonly used in preparing deep wellbores in the Norwegian Sea, which contains 784 L/m3 of cesium formate brine and 132 L/m3 of potassium formate brine, is commonly buffered with from about 2,000 to about 3,000 ppm of potassium carbonate.
Unfortunately, when a conventional cement slurry is pumped into a wellbore behind a drilling fluid buffered in this manner, it can be adversely affected by the alkaline material and the formate in the drilling fluid. For example, the alkaline material may cause the thickening time of the cement slurry to become unacceptably short for safe placement in the wellbore, or it can cause the cement slurry to attain a consistency at which it is unpumpable. As such, the drill pipe or the tool used to lower the piping in the wellbore may be cemented in place, causing several weeks of delay in the completion of the well. Attempts to reduce this effect on thickening time by including more set retarder than usual in the cement slurry may highly increase the time required for the slurry to develop a strength sufficient to form an impermeable solid. As a result of these problems, the cost of preparing the wellbore may be very high. A need therefore exists for methods of reducing the impact of an alkaline material and a formate compound present in a drilling fluid on a cement slurry while still achieving the desired strength for the cement within an acceptable amount of time.